London — The UK's National Grid is looking to make the case for blending hydrogen into the natural gas network as it navigates its role in the country's transition to a low-carbon economy, the company's Project Director for Hydrogen, Antony Green, told S&P Global Platts.
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"The existing national gas transmission asset provides a valuable option for decarbonization if we can demonstrate a move to hydrogen is possible," Green said in an interview April 27.
"The work that we're doing over the next few years is to develop the evidence base."
National Grid is working on a test facility to prove the natural gas network can handle various blends of hydrogen, starting at 2%, then 20% and eventually 100%. This would provide the evidence base for the necessary changes to legal mechanisms and safety procedures for the network, Green said.
"Blending is an enabler to get to 100%," Green said.
Green noted systems already in operation that run high hydrogen blends in their gas grids, such as Hong Kong which operates on town gas, which is 50% hydrogen.
"All of the international research suggests that we would be able to do it," Green said.
For medium-level blends upwards, compression infrastructure and some pipelines will need to be replaced or retrofitted. Original equipment manufacturers indicate the turbines used are ready to take hydrogen blends of 10%-30% with some retrofitting, though these estimates are rising as further research is conducted, he said.
The gas distribution network is already mostly plastic pipelines, and a replacement program is in place for the remainder of the metallic pipes.
Steel mains pipes are more prevalent in the transmission network, and hydrogen embrittlement can become a concern, where pipes can crack more easily. However, embrittlement is more of an issue when hydrogen is used in chemical processes in ionic form, and with large variations in pressure and temperature, Green said, rather than for hydrogen transmission.
It is widely accepted that natural gas networks can handle blends of up to 20% hydrogen without significant changes to existing infrastructure, Green said, though noted the carbon benefit was significantly smaller, as hydrogen has a third of the calorific value of natural gas by volume.
Beyond the 20% level, domestic boilers need to be changed to run on higher mixes of hydrogen, which is the main constraint to hydrogen blending at present. Green said a program of fitting hydrogen-ready boilers in homes would be a "very interesting step" which could be started now, enabling gas networks to switch to higher hydrogen blends in the future.
The National Grid launched Project Union in March to develop a UK hydrogen "backbone" connecting the industrial clusters identified in the UK government's industrial decarbonization strategy with a 2,000 km network of 100% hydrogen pipelines by 2030.
The project would repurpose around 25% of current gas transmission pipelines, and could carry "at least a quarter" of current British gas demand, National Grid said, connecting clusters in Grangemouth, Teesside, Humberside, the North West, South Wales and Southampton.
Project Union would build resilience between the hubs, Green said, reducing the need for additional production or storage facilities in any single location.
The project will explore connections to existing interconnectors at Bacton, where the UK could link with the EU hydrogen backbone in development.
National Grid is also investigating hydrogen supply from the Isle of Grain to London, under Project Cavendish. Green said National Grid had identified the pipework needed and potential primary users in the power generation sector around the Isle of Grain, and the next stage would be pre-front end engineering design.
Hydrogen supply options to the Isle of Grain include decarbonizing existing LNG supplies to the terminal there, or routing natural gas to the terminal for decarbonization. One option under consideration would be to use existing jetties at the Isle of Grain to ship CO2 out to proposed offshore storage in the North Sea.
National Grid is agnostic on the various renewable and low-carbon hydrogen production pathways under development, but Green sees low-carbon "blue" hydrogen -- produced via steam methane reforming combined with carbon capture and storage technology -- as a transition fuel.
"At a transmission level, I think we have to start with blue because that's where the scale will come from," he said. "It allows us to decarbonize most rapidly, particularly around industry. That, in parallel, then lets green start to mature and the price points start to drop."
Green hydrogen, produced by electrolyzing water with renewable electricity, could have wider applications in the hard to decarbonize sectors such as fuel cells for heavy transport, Green said, as the purity is higher.
"Once you've got renewable generation starting to come onshore from the North Sea, you can start to build out green hydrogen at larger scale, and you'll start to see a displacement of blue," he said, adding that the technology could still be in use in 50 years or longer, and may still be in use post net-zero.